Methods of Limiting Leak Off and Damage in Hydraulic Fractures

ABSTRACT

Methods for treating a formation penetrated by a wellbore which improves fluid loss control during treatment. In some aspects, the treatments include preparing an aqueous fluid including one or more water inert polymers and an optional viscosifier, injecting the aqueous fluid into the wellbore at a pressure equal to or greater than the formation&#39;s fracture initiation pressure, and thereafter injecting into the wellbore a proppant laden fluid at a pressure equal to or greater than the formation&#39;s fracture initiation pressure. The water inert polymer may be a polymer such as an emulsion polymer or a latex polymer. Some methods of the invention use a fluid which may have a normalized leak off coefficient (C w /sqrt(K)) equal to or less than about 0.0022, 0.0014, or 0.0010. A conventional fluid loss additive may or may not be used in conjunction with the treatment fluid and/or the proppant laden fluid. The water inert polymer may or may not substantially enter formation pores. In another aspect, methods for reducing matrix damage to a formation during a treatment operation include preparing an aqueous treatment fluid formed of at least one water inert polymer, and injecting the fluid at a pressure equal or greater than the formation&#39;s fracture initiation pressure.

TECHNICAL FIELD OF THE INVENTION

This invention relates to improving the production of fluids from wellspenetrating subterranean formations. More particularly, this inventionrelates to methods using stabilized aqueous dispersions of water inertpolymers in treatment fluids to improve fluid efficiency duringhydraulic fracture treatments while minimizing or preventing proppantpack damage.

BACKGROUND OF THE INVENTION

Hydraulic fracturing of oil or gas wells is a technique routinely usedto improve or stimulate the recovery of hydrocarbons. In such wells,hydraulic fracturing is usually accomplished by introducing aproppant-laden treatment fluid into a producing interval at highpressures and at high rates sufficient to crack the rock open. Thisfluid induces a fracture in the reservoir as it leaks off in thesurrounding formation and transports proppant into the fracture. Afterthe treatment, proppant remains in the fracture in the form of apermeable and porous proppant pack that serves to maintain the fractureopen as hydrocarbons are produced. In this way, the proppant pack formsa highly conductive pathway for hydrocarbons and/or other formationfluids to flow into the wellbore.

Typically, viscous fluids or foams are employed as fracturing fluids inorder to provide a medium that will have sufficient viscosity to crackthe rock open, adequately suspend and transport solid proppantmaterials, as well as decrease loss of fracture fluid to the formationduring treatment (commonly referred to as “fluid loss”). While a reducedfluid loss allows for a better efficiency of the treatment, a higherfluid loss corresponds to fluids “wasted” in the reservoir, and impliesa more expensive treatment. Also, it is known that the degree of fluidloss can significantly depend upon formation permeability. Furthermorefluid efficiency of a fracture fluid may affect fracture geometry, sincethe viscosity of the fluid might change as the fluid is lost in theformation. This is the case for polymer-based fracturing fluids thatconcentrate in lower permeability formations as the fracture propagatesdue to leak off of the water in the formation, while the polymermolecules remain in the fracture by simple size exclusion from the poresof the reservoir. The fluid in the fracture increases in viscosity asthe fracture propagates and the fracture generated will also increase inwidth as well as in length. In the case of viscoelastic surfactant (VES)based fluids, the fracturing fluid does not concentrate since thefracturing fluid is lost in the formation and typically the fracturesgenerated are long and very narrow. Hence, fluid efficiency affectsfracture geometry.

For VES based fluids, excessive fluid loss results in fractures that arenarrower than desired. Also, excessive fluid loss may translate intosignificant job size where hundreds of thousands of additional gallonsof water may be pumped to generate the required length of fracture andovercome low fluid efficiency. Fracturing fluids should have a minimalleak-off rate to avoid fluid migration into the formation rocks andminimize the damage that the fracturing fluid or the water leaking offdoes to the formation. Also the fluid loss should be minimized such thatthe fracturing fluid remains in the fracture and can be more easilydegraded, so as not to leave residual material that may preventhydrocarbons to flow into the wellbore.

Early fracturing fluids were constituted of viscous or gelled oil but,with the understanding that formation damage due to water may not be asimportant as originally thought, aqueous fracturing fluids mainlyconsisting of “linear” polymeric gels comprising guar, derivatized guar,cellulose, or derivatized cellulose were introduced. In order to attaina sufficient fluid viscosity and thermal stability in high temperaturereservoirs, linear polymer gels were partially replaced by cross-linkedpolymer gels such as those based on guar crosslinked with borate orpolymers crosslinked with metallic ions. However, as it became apparentthat crosslinked polymer gel residues might not degrade completely andleave a proppant pack with an impaired retained conductivity, fluidswith lower polymer content were introduced. In addition, some additiveswere introduced to improve the cleanup of polymer-based fracturingfluids. These included polymer breakers. Nonetheless the polymer basedfracturing treatments leave proppant pack with damaged retainedconductivity since the polymer fluids concentrate in the fracture whilethe water leaks off in the reservoir that may impair the production ofhydrocarbons from the reservoir.

Other fracturing fluids with improved cleanup, i.e. that leave aproppant pack with higher retained conductivity, have been developed.Examples are fluids that use viscoelastic surfactants (VES) asviscosifiers. The viscoelastic surfactant molecules, when present at asufficient concentration, may aggregate into overlapping worm- orrod-like micelles, which confer the necessary viscosity to the fluid tocarry the proppant during fracturing. At very high shear rate however,the viscosity may decrease. Also, the surfactant worm- or rod-likemicelles tend to disaggregate by contact with hydrocarbons and, if nosurfactant emulsion is effectively formed, the surfactant molecules arenormally carried along the fracture, to the well bore, during thehydrocarbon backflow.

Yet another approach to limit the damage of the proppant pack, is to usewater based treatments with friction reducers (referred as slickwatertreatments), and pump the fracturing fluids at much higher rates in theformation. The proppant is carried to the formation due to the high flowrates. The limitation of the treatments is that the maximum proppantconcentration that can be placed is limited to a small concentrationsince the fluid has low viscosity. Another limitation is very low fluidefficiency and therefore the size of the slickwater treatments.

Based on reservoir simulations and field data, it is commonly observedthat production resulting from a fracturing treatment is often lowerthan expected. This phenomenon is particularly the case in tight gasformations. Indeed, production can be decreased significantly byconcentrated polymer left in the fracture due to leak off of thefracturing fluid during treatment. Filter cakes may result in poorproppant pack cleanup due to the yield stress properties of the fluid.This may happen when a crosslinked polymer based fluid is pumped thatleaks off into the matrix and becomes concentrated, and extremelydifficult to remove. Breaker effectiveness may thus become reduced, andviscous fingering inside the proppant pack may occur which furtherresults in poor cleanup. Furthermore, the filter cake yield stresscreated by the leak off process can occlude the fracture width andrestrict fluid flow, resulting in a reduction in the effective fracturehalf-length.

Accordingly, there is a need for methods for treating subterraneanformations using fluids which enable efficient pumping, whichsignificantly decrease and control the leak off relative to conventionalfracturing treatments in order to reduce the damage to the production,while having good cleanup properties as well as improved fluidefficiency (i.e. providing less expensive and time-consuming treatment).These needs are met, at least in part, with the following invention.

SUMMARY OF THE INVENTION

Disclosed are methods for treating a formation penetrated by a wellborewhich improves fluid loss control during treatment. In some aspects, themethods are slickwater treatments which include preparing an aqueousfluid comprising at least one water inert polymer, where a viscosifieris not added to the aqueous fluid to substantially increase the fluidviscosity, then injecting the aqueous fluid into the wellbore at apressure equal to or greater than the formation's fracture initiationpressure, and thereafter injecting into the wellbore a proppant ladenfluid at a pressure equal to or greater than the formation's fractureinitiation pressure. In some embodiments of the invention, the waterinert polymer includes one or more emulsion polymers, while in otherembodiments, the water inert polymer may be at least one latex polymer.When the water inert polymer is formed of a plurality of latexes, theymay be a mixture of latexes of different particle sizes. Some methods ofthe invention use a fluid which may have a normalized leak offcoefficient (C_(w)/sqrt(K)) equal to or less than about 0.0022,preferably equal to or less than about 0.0010. A conventional fluid lossadditive may or may not be used in conjunction with the treatment fluidand/or the proppant laden fluid.

The water inert polymer may form a film on fracture faces, and the filmmay optionally be at least partially degraded during and/or subsequentto injecting the proppant laden fluid. When the film is degraded, it maybe degraded with a breaker, such as a delayed breaker, a conventionaloxidizer, an oxidizer triggered by catalysts contained in the film, alatent acid, or formation fluids. Also, the water inert polymer may ormay not substantially enter the formation pores. Methods of theinvention may use a fluid further including one or more of thefollowing: a gas component, acid particles, colloidal particles, atleast one friction pressure reducing agent, and the like.

In another aspect of the invention, the methods are formation treatmentswhich include first preparing an aqueous pad fluid containing at leastone water inert polymer and a viscosifier, injecting the aqueous fluidinto the wellbore at a pressure equal to or greater than the formation'sfracture initiation pressure, and injecting a proppant laden fluid at apressure equal to or greater than the formation's fracture initiationpressure. While any suitable water inert polymer may be used, thepolymer may be one or more latex or emulsion polymers. A conventionalfluid loss additive may or may not be incorporated into the fluids, aswell as any other commonly used additives or components. Some methods ofthe invention use a fluid which may have a normalized leak offcoefficient equal to or less than about 0.0022, preferably equal to orless than about 0.0014, more preferable equal to or less than about0.0010. Some examples of viscosifiers useful in the fluids includeviscoelastic surfactants, natural polymers, derivatives of naturalpolymers, synthetic polymers, biopolymers, and the like, or any mixturesthereof. The water inert polymer may form a film on fracture faces,which may be subsequently degraded. The water inert polymer may or maynot substantially enter formation pores.

In yet another aspect, disclosed are methods for reducing matrix damageto a formation during a treatment operation, by first preparing anaqueous treatment fluid formed of at least one water inert polymer, andinjecting the fluid at a pressure equal or greater than the formation'sfracture initiation pressure. The fluid may or may not include aviscosifier such as a polymer or viscoelastic surfactant.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows, by graphical representation, the measured viscosity offluids with and without emulsion type water inert polymer.

FIG. 2 illustrates fluid loss improvements for fluids containingemulsion water inert polymer blended with conventional fracturing padfluids.

FIG. 3 represents normalized leak-off coefficients (C_(w)/Sqrt(K)) forpad fluids with and without emulsion type water inert polymers.

FIG. 4 indicates the effect of removing an emulsion based film using anammonium persulfate breaker.

FIG. 5 shows the rheology of a 25 ppt crosslinked guar system containing2 gpt of a liquid clay stabilizer solution and a nanolatex based waterinert polymer.

FIG. 6 is a plot of normalized C_(w) coefficients measured on differentcores at 85° F. with various amounts of latex water inert polymer.

FIG. 7 shows the same data as FIG. 6, reported as normalized C_(w)coefficient versus latex water inert polymer concentration.

FIG. 8 graphically represents a plot of normalized C_(w) coefficientsfor different latex water inert polymers, and blends thereof.

FIG. 9 illustrates the results of a conventional static fluid loss testusing 1″ cores for pad fluids with and without a latex water inertpolymer.

FIG. 10 illustrates the additional advantage of using a latex waterinert polymer in conjunction with a fluid loss additive.

FIG. 11 shows leak off rates for VES based pad fluids with and withoutemulsion water inert polymers.

DETAILED DESCRIPTION

The description and examples are presented solely for the purpose ofillustrating the preferred embodiments of the invention and should notbe construed as a limitation to the scope and applicability of theinvention. While the compositions of the present invention are describedherein as comprising certain materials, it should be understood that thecomposition could optionally comprise two or more chemically differentmaterials. In addition, the composition can also comprise somecomponents other than the ones already cited. In the summary of theinvention and this detailed description, each numerical value should beread once as modified by the term “about” (unless already expressly somodified), and then read again as not so modified unless otherwiseindicated in context. Also, in the summary of the invention and thisdetailed description, it should be understood that a concentration rangelisted or described as being useful, suitable, or the like, is intendedthat any and every concentration within the range, including the endpoints, is to be considered as having been stated. For example, “a rangeof from 1 to 10” is to be read as indicating each and every possiblenumber along the continuum between about 1 and about 10. Thus, even ifspecific data points within the range, or even no data points within therange, are explicitly identified or refer to only a few specific, it isto be understood that inventors appreciate and understand that any andall data points within the range are to be considered to have beenspecified, and that inventors possession of the entire range and allpoints within the range.

In embodiments of the disclosed method, fluid loss control duringfracture treatments may be improved by the use of water inert polymers,which includes water inert polymer particles. As a result of includingthe polymers, the efficiency of the fracture treatments are surprisinglyimproved. As used herein, “water inert polymers” refers to polymerswhich during a well treatment time period, have no substantial affinityfor water, are not significantly water interactive, nor do theysubstantially expand or increase (as in size, volume, or numbers) beyonda normal or original limit. Water inert polymers differ from hydratablepolymers, which at least partially dissolve in water and are commonlyused in treatment fluids as viscosifying agents. Water inert polymersalso differ from hydrophilic swelling polymers (oftentimes referred toas “superabsorbing particles”, “hydrogels”, “water swellable polymers”,“water swellable particles” and the like) based on synthetic polymersthat are unable to hydrate, but when interacting with water, may swellup to many times their original size, such as those described in U.S.Pat. No. 6,169,058. As used herein, the term “ppt” describes theconcentration of a material, or materials, in pounds per thousandgallons fluid. Also, the term “gpt” is defined as gallons per thousandgallons of fluid.

Although not bound by or limited to any particular theory or mechanismof operation, fluid loss control during treatments may be improved bythe use of water inert polymers due to film forming. For example, asubstantially water impermeable film, also referred to as a “membrane”for purposes herein, may be deposited on the fracture face as a resultof dehydration or agglomeration of the water inert polymer. Theformation of a water inert polymer based film arises from “coalescence”of the polymer or polymer particles, such as latex particles or emulsionparticles, which are normally separated by stabilizing forces(electrostatic or steric) augmented with a stabilizing surfactant. Theseforces may be overcome upon evaporation or dehydration of the continuousliquid carrier phase. See “An Overview of Polymer Latex Film Formationand Properties”, P. A. Steward, J. Hearn, & M. C. Wilkinson, Advances inColloid and Interface Science, 85 (2000) 195-267). Thus, the water inertpolymer is delivered to the formation fracture faces dispersed andstabilized in an aqueous medium, the water and stabilizing thesurfactant is then substantially removed by loss into the formationwhile the water inert particles remain within or near the fractureregion, thus forming a film on the fracture faces. The water inertparticles may or may not substantially enter pores on the formationfracture faces.

In some embodiments, after placement of proppant in the fracture using aproppant laden fluid which may or may not contain a viscosifier, thefilm formed from the water inert polymers may be broken down or degradedduring flowback and/or production stages. Film degradation may beachieved by delayed breakers (such as conventional oxidizers or byoxidizers triggered by a catalyst contained in the film), by hydrolysisof a latent acid such as polylactic acid (PLA) or polyglycolic acid(PGA) based fibers deposited with the film, by temperature, byinstability of the film in formation fluids, by dissolution of the filmin formation fluids, and the like. Formation production may be increasedbecause little or no filter cake of highly concentrated polymer isformed which typically reduces the available fracture width, promotesviscous fingering, generates a high yield stress fluid and alters thepack porosity and permeability. Also, less matrix damage from leak offof damaging fluid exists. Further, breaker efficiency can be optimizedin conjunction with the placement of the water inert polymer. Methods ofthe invention may significantly limit the damage caused by a high leakoff during wellbore treatments using conventional treatment fluids, suchas slickwater, polymer based fracturing fluids, viscoelastic surfactantbased fracturing fluids, or foamed fluids, for example.

Another advantage provided by the invention is a potential decrease inthe time and resources required to complete treatment operations. Forexample, a typical slickwater fracturing operation requires on the orderof approximately 500,000 gallons of water be pumped into the wellboreover the course of treatment. In a typical polymer based treatment,commonly, on the order of approximately 100,000 gallons of water isrequired. These water volumes may be reduced by half or more, which mayalso translate into collateral decreases in job time, overall poweroutput requirements, as well as fluid ingredient consumption. In thoseinstances where requisite water volumes are not readily available,methods of the invention overcome such a limitation since resourceconsumption may be significantly reduced.

Yet another advantage of methods of the invention is a reduction inmatrix damage due to a decrease in the amount of fluid which leaks offinto the formation. Matrix damage can occur to some extent whenviscoelastic surfactant based viscosifiers are used, or in the case ofslickwater operations where the fluid has no significant proppantcarrying capacity. In these cases, the leak off may be controlled by theviscosity of the fluid itself and the permeability of the reservoir.This advantage is particularly applicable for formations as low as 0.001milli-Darcy (mD) permeability to as high as 1 Dsarcy permeability.

In some method embodiments of the invention, a polymer based aqueousfracturing fluid is introduced into the wellbore, but does not form asignificant filter cake. In the case of conventional fluids where asignificant filter cake is typically formed, the higher the leak off themore concentrated the polymer in the fracture will be, which increasesviscous fingering effects and reduces significantly the effectiveness ofbreakers. Also the filter cake may behave as a yield stress fluid andbecomes difficult to clean and remove from the fracture. By using filmforming water inert polymer, the leak off may be significantly reducedand the polymer is concentrated in the fracture, improving the retainedproppant pack conductivity and reducing the flow initiation pressure ofthe fracturing fluid during flowback.

Methods of the invention are suitable for treating formations containingpetroleum products, such as oil and gas, as well as injection wells.Although the invention may be practiced in any suitable formationcondition, the most practical temperature range of application is fromabout 20° C. to about 180° C. In preferred applications, formationpermeability is about 100 Darcy or less.

In some embodiments of the invention, a film which is substantially gaspermeable is formed. Such a gas permeable film may develop from the“coalescence” of water inert polymer particles, but only to such anextent that gas may permeate the film. Other practical means for formingsuch films will be readily known to those of skill in the art. Forpurposes herein, the term gas permeable film means a thin polymer filmwhich selected gas molecules will pass, either through capillary poresin the film.

Because the water inert polymer does not impart substantial viscosity,in some embodiments the water inert polymer will be blended with a fluid(PAD fluid) containing a viscosifier and then may coat fracture faceswith a substantially impermeable film as the fracture is created. Thetreatment (pad) fluids may be, among other things, linear, crosslinked,gelled, or foamed fluids formed with typical viscosifiers (i.e. polymersor viscoelastic surfactants) and additives known to those of skill inthe art. When used in treatments, the pad (neat fluid) is commonlypumped first, or in some cases subsequent to a pre-PAD fluid, to createfractures and establish propagation (i.e. the fracture grows up and downas well as out). Then, a proppant laden slurry fluid is pumped intofractures, and may continue to extend the fractures and concurrentlycarry and place the proppant deep into the fractures. Nonlimitingexamples of viscosifiers useful in pad fluids include conventionalhydratable polymers such as guar and its derivatives, polyacrylamide andits derivatives, cellulose and its derivatives, xanthan, viscoelasticsurfactants, sphingan heteropolysaccharides, and the like. Fluids usinga water inert polymer in conjunction with a viscosifier are particularlyuseful for pad applications. In another embodiment, the water inertpolymer will be used along with the first stage of a slickwatertreatment with or without the friction reducers conventionally used withsuch treatments. The water inert polymer will then coat fracture faceswith a substantially impermeable film as the fracture extends.

Some embodiments of the invention are based upon a three-step treatment.First is the introduction of the so-called pad or treatment fluid intothe wellbore and formation, in which the water inert polymer is used toform a film, temporarily or permanently, which is substantially waterimpermeable. The film may form on the fracture faces due to dehydrationand/or agglomeration of the water inert polymer. In the second step,which may or may not be simultaneous with the first step, conventionalfracturing treatment fluid and proppant stages are introduced into theformation, showing minimal (significantly reduced) leak off due to thepresence of the film. The third step is to achieve film breakdown duringthe flowback and production stages. Breakdown may be achieved by delayedbreakers such as conventional oxidizers or by oxidizers triggered by acatalyst contained in the film, by hydrolysis of a latent acid such asPLA particles, granulated particles or fibers deposited with or afterthe film is placed, by temperature, by instability of the film in thepresence of produced fluids, and the like.

The water inert polymers useful in embodiments of the invention aredispersed and stabilized in an aqueous medium. Any suitable means ofstabilizing and dispersing the polymer in an aqueous medium may by used.The actual technique used is not particularly important as long as thepolymer, or polymer particle, remains dispersed in the aqueous medium atleast for the time period necessary for delivery to the formation.

As the water inert polymers encounter the formation rock in early stagesof the treatment, it should be compatible with conventional fracturingfluids and not the rheological properties of a pad treatment. The waterinert polymers should also be compatible with conventional additives,including, but not limited to, clay control additives, iron controladditives, foamers, scale control additives, pH buffers, temperaturestabilizers, and the like. Water inert polymers useful in the inventionmay provide reduced leak-off by forming a film to create a substantiallywater impermeable film on the fracture faces. The water inert polymersshould be substantially removable. In order to allow for improvedproduction the permeability of the fracture faces should be restored atleast partially or locally such that the flow from the formation to thefracture can be resumed. Common breakers typically used includesconventional oxidizers with or without a catalyst, conventional enzymes,acids, latent acids such as PLA or PGA, or the like, and elevatedtemperature.

In some embodiments, the water inert polymer may be a latex resin (alsotermed latex polymer) stabilized in an aqueous medium. As used herein,the terms “latex resin”, “latex”, or “latex polymer” refers to adispersion of a water inert polymer which may be prepared bypolymerization techniques such as, for example, by emulsionpolymerization, and further, includes polymers prepared by thesetechniques where the average diameter size of the dispersed polymerranges from the nano scale, such as nanolatexes, to microgels which areon the order of from about 10⁻³ microns to about 10³ microns indiameter, including any functional diameter therebetween. The latexpolymer may be an aqueous emulsion of finely divided polymer particles.Any practical blend of latex size may be used in accordance with theinvention, such as a blend of a latex polymer and a nanolatex polymer.For purposes of this disclosure, the terms “latexes” and “lattices” havethe same meaning.

Latex polymers are prepared synthetically by polymerizing monomers thathave been emulsified with surfactants. For example, in preparing latexby emulsion polymerization, typically a surfactant is dissolved in wateruntil a critical micelle concentration (CMC) is reached. The interior ofthe micelle provides the site necessary for polymerization. In somepreparations, a monomer (like styrene, hydroxyl ethyl acrylate, methylmethacrylate, and the like) and a water-soluble free radical initiatorare added and the whole batch is mixed to form the polymer. Core-shelllatexes are also useful in some embodiments of the invention. Readilyknown to those of skill in the art, preparation of core-shell latexes iscommonly performed by two-stage emulsion. In the first stage a waterinert polymer is formed as the core by emulsion polymerization. In asecond stage, polymerization of a shell surrounding the core is preparedby emulsion polymerization. Typically latex resins (polymers) arestabilized in the aqueous environment by surfactants, functionality ofthe shell in a core-shell latex, or combination of surfactant andfunctionality of the shell. Nonlimiting examples of latex types, whichmay be useful, include latexes of acrylic copolymers, polyvinyl alcohol,polyvinyl acetate, polyvinyl esters such as vinyl versatic acid,crosslinked polyvinyl alcohol, vinyl acetate, polyvinyl pyrrolidone,polystyrene, polystyrene butadiene copolymers, and the like. Anysuitable latex may be used according to the invention. Some examples oflatexes which may be useful include, but are not necessarily limited to,latexes available from Hexion Specialty Chemicals, Inc., Columbus, Ohio43215, such as RHODOPAS® LS500, RHODOPAS® D2400, RHODOPASS® D2600,Schlumberger D500, or Schlumberger D600G. When incorporated as a waterinert polymer, the latex polymer amount may vary from about 0.1% toabout 50% by weight, based upon total fluid weight, The lower limit ofthe latex amount being no less than about 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7,8, 9, 10, or 15% by weight, based upon total fluid weight, and the upperlimit being no greater than 50, 45, 40, 35, 30, 25, 24, 23, 22, 21, or20% by weight, based upon total fluid weight. Preferably the latex isincorporated in an amount from about 1% to about 20% by weight, basedupon total fluid weight, more preferably from about 5% to about 15% byweight, based upon total fluid weight.

Another approach is the use of an emulsion, where the water inertpolymer is emulsified in the aqueous medium. As used herein, an“emulsion” refers to a dispersion of water inert polymers or water inertpolymer particles in an aqueous medium with which the water inertpolymers or water inert polymer particles will not readily mix. Someemulsions useful in the invention are mixtures of polymer and liquid, inwhich the polymer is dispersed in the liquid as small, microscopic orultramicroscopic droplets (see colloid). Emulsions are stabilized byagents (emulsifiers) that form films at the droplets' surface and/orimpart mechanical stability. Less-stabilized emulsions eventuallyseparate spontaneously into two layers; more-stabilized ones can bedestroyed by inactivating the emulsifier, by dehydration of theemulsifier, by concentrating the emulsion or by heating. Nonlimitingexamples of emulsion types which may be useful in the invention includeemulsions of polyethylene (PE), high density polyethylene (HDPE),polypropylene, polyethylene/polypropylene mixtures, paraffin, polyvinylalcohol, epoxy polymer, polyurethane, crosslinked polyvinyl alcohol,crosslinked polyvinyl alcohol / polyvinyl acetate mixtures, and thelike.

When incorporated as a water inert polymer, the emulsion polymer amountmay vary from about 0.1% to about 50% by weight, based upon total fluidweight, The lower limit of the emulsion amount being no less than about0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or 15% by weight, based upontotal fluid weight, and the upper limit being no greater than 50, 45,40, 35, 30, 25, 24, 23, 22, 21, or 20% by weight, based upon total fluidweight. Preferably the emulsion is incorporated in an amount from about1% to about 20% by weight, based upon total fluid weight, morepreferably from about 5% to about 15% by weight, based upon total fluidweight.

Any suitable emulsion polymer may be used. Some examples of emulsionswhich may be useful according to the invention include, but are notnecessarily limited to, those emulsions available from ChemCor, Chester,N.Y., 10918, USA, such as PolyEMULSION 330N35 which is a 35% solids,nonionic emulsion of Honeywell Corporation's AC 330 high densitypolyethylene, or polyEMULSION 629N40, that is a non-ionic, fine particlesize emulsion of Honeywell Corporation's AC-629 polyethylene.

The water inert polymer may also be a water reducible polymer. By “waterreducible” it is meant that the polymer is dispersible in water uponneutralization. Such polymers shall commonly be rendered waterdispersible though ionic, nonionic, ionic/nonionic hydrophilicfunctionality. Nonlimiting examples include low acid number waterdispersible polymers, which may have ionic, or mixed ionic/nonionicstabilization.

The aqueous medium of fluids useful of the invention may be water orbrine. Where the aqueous medium is a brine, the brine is watercomprising an inorganic salt(s), organic salt(s), or mixture(s) thereof.Preferred inorganic salts include alkali metal halides, more preferablypotassium chloride or ammonium chloride. The carrier brine phase mayalso comprise an organic salt more preferably sodium or potassiumformate, or tetra-methyl ammonium chloride. Preferred inorganic divalentsalts include calcium halides, more preferably calcium chloride orcalcium bromide. Sodium bromide, potassium bromide, or cesium bromidemay also be used.

Fluids useful in the invention may also include a viscosifier that maybe a polymer that is either crosslinked or linear, a viscoelasticsurfactant, or any combination thereof Some nonlimiting examples ofsuitable polymers include guar gums, high-molecular weightpolysaccharides composed of mannose and galactose sugars, or guarderivatives such as hydropropyl guar (HPG), carboxymethyl guar (CMG),and carboxymethylhydroxypropyl guar (CMHPG). Cellulose derivatives suchas hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) andcarboxymethylhydroxyethylcellulose (CMHEC) may also be used in eithercrosslinked form, or without crosslinker in linear form. Xanthan,diutan, and scleroglucan, three biopolymers, have been shown to beuseful as viscosifying agents. Synthetic polymers such as, but notlimited to, polyacrylamide and polyacrylate polymers and copolymers areused typically for high-temperature applications. Nonlimiting examplesof suitable viscoelastic surfactants useful for viscosifying some fluidsinclude cationic surfactants, anionic surfactants, zwitterionicsurfactants, amphoteric surfactants, nonionic surfactants, andcombinations thereof. Also, associative polymers for which viscosityproperties are enhanced by suitable surfactants and hydrophobicallymodified polymers can be used, such as cases where a a charged polymerin the presence of a surfactant having a charge that is opposite to thatof the charged polymer, the surfactant being capable of forming anion-pair association with the polymer resulting in a hydrophobicallymodified polymer having a plurality of hydrophobic groups, as describedpublished U.S. Pat. App. No. US 2004/209,780, Harris et. al.

In some method embodiments, the viscosifier is a water-dispersible,linear, nonionic, hydroxyalkyl galactomannan polymer or a substitutedhydroxyalkyl galactomannan polymer. Examples of useful hydroxyalkylgalactomannan polymers include, but are not limited to,hydroxy-C₁-C₄-alkyl galactomannans, such as hydroxy-C₁-C₄-alkyl guars.Preferred examples of such hydroxyalkyl guars include hydroxyethyl guar(HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HBguar), and mixed C₂-C₄, C₂/C₃, C₃/C₄, or C₂/C₄ hydroxyalkyl guars.Hydroxymethyl groups can also be present in any of these.

As used herein, substituted hydroxyalkyl galactomannan polymers areobtainable as substituted derivatives of the hydroxy-C₁-C₄-alkylgalactomannans, which include: 1) hydrophobically-modified hydroxyalkylgalactomannans, e.g., C₁-C₁₈-alkyl-substituted hydroxyalkylgalactomannans, e.g., wherein the amount of alkyl substituent groups ispreferably about 2% by weight or less of the hydroxyalkyl galactomannan;and 2) poly(oxyalkylene)-grafted galactomannans (see, e.g., A. Bahamdan& W. H. Daly, in Proc. 8PthP Polymers for Adv. Technol. Int'l Symp.(Budapest, Hungary, September 2005) (PEG- and/or PPG-grafting isillustrated, although applied therein to carboxymethyl guar, rather thandirectly to a galactomannan)). Poly(oxyalkylene)-grafts thereof cancomprise two or more than two oxyalkylene residues; and the oxyalkyleneresidues can be C₁-C₄ oxyalkylenes. Mixed-substitution polymerscomprising alkyl substituent groups and poly(oxyalkylene) substituentgroups on the hydroxyalkyl galactomannan are also useful herein. Invarious embodiments of substituted hydroxyalkyl galactomannans, theratio of alkyl and/or poly(oxyalkylene) substituent groups to mannosylbackbone residues can be about 1:25 or less, i.e. with at least onesubstituent per hydroxyalkyl galactomannan molecule; the ratio can be:at least or about 1:2000, 1:500, 1:100, or 1:50; or up to or about 1:50,1:40, 1:35, or 1:30. Combinations of galactomannan polymers according tothe present disclosure can also be used.

As used herein, galactomannans comprise a polymannose backbone attachedto galactose branches that are present at an average ratio of from 1:1to 1:5 galactose branches:mannose residues. Preferred galactomannanscomprise a 1→4-linked β-D-mannopyranose backbone that is 1→6-linked toα-D-galactopyranose branches. Galactose branches can comprise from 1 toabout 5 galactosyl residues; in various embodiments, the average branchlength can be from 1 to 2, or from 1 to about 1.5 residues. Preferredbranches are monogalactosyl branches. In various embodiments, the ratioof galactose branches to backbone mannose residues can be,approximately, from 1:1 to 1:3, from 1:1.5 to 1:2.5, or from 1:1.5 to1:2, on average. In various embodiments, the galactomannan can have alinear polymannose backbone. The galactomannan can be natural orsynthetic. Natural galactomannans useful herein include plant andmicrobial (e.g., fungal) galactomannans, among which plantgalactomannans are preferred. In various embodiments, legume seedgalactomannans can be used, examples of which include, but are notlimited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum(e.g., from Cyamopsis tetragonoloba seeds). In addition, althoughembodiments of the present invention may be described or exemplifiedwith reference to guar, such as by reference to hydroxy-C₁-C₄-alkylguars, such descriptions apply equally to other galactomannans, as well.

When incorporated, the polymer based viscosifier may be present at anysuitable concentration. In various embodiments hereof, the gelling agentcan be present in an amount of from about 10 to less than about 60pounds per thousand gallons of liquid phase, or from about 15 to lessthan about 40 pounds per thousand gallons, from about 15 to about 35pounds per thousand gallons, 15 to about 25 pounds per thousand gallons,or even from about 17 to about 22 pounds per thousand gallons.Generally, the gelling agent can be present in an amount of from about10 to less than about 50 pounds per thousand gallons of liquid phase,with a lower limit of polymer being no less than about 10, 11, 12, 13,14, 15, 16, 17, 18, or 19 pounds per thousand gallons of the liquidphase, and the upper limited being less than about 50 pounds perthousand gallons, no greater than 59, 54, 49, 44, 39, 34, 30, 29, 28,27, 26, 25, 24, 23, 22, 21, or 20 pounds per thousand gallons of theliquid phase. In some embodiments, the polymers can be present in anamount of about 20 pounds per thousand gallons. Hydroxypropyl guar,carboxymethyl hydroxypropyl guar, carboxymethyl guar, cationicfunctional guar, guar or mixtures thereof, are preferred polymers foruse herein as a gelling agent. Fluids incorporating polymer basedviscosifiers preferably have a viscosity value of at least about 100centipoise at a shear rate of about 100 s⁻¹, at treatment temperature.

As a viscoelastic surfactant based viscosifier, any suitableviscoelastic surfactant may be used in accordance with the invention.Preferably the viscoelastic surfactant is an ionic VES. By ionic it ismeant that the VES may be cationic, anionic or zwitterionic depending onthe charge of its head group. When the surfactant is cationic, it isassociated with a negative counterion, which can be an inorganic anionsuch as a sulfate, a nitrate, a perchlorate or a halide such as Cl⁻, Br⁻or with an aromatic organic anion such as salicylate, naphthalenesulfonate, p and m chlorobenzoates, 3,5 and 3,4 and2,4-dichlorobenzoates, t-butyl and ethyl phenate, 2,6 and2,5-dichlorophenates, 2,4,5-trichlorophenate,2,3,5,6-tetrachlorophenate, p-methyl phenate, m-chlorophenate,3,5,6-trichloropicolinate, 4-amino-3,5,6-trichlorpicolinate,2,4-dichlorophenoxyacetate. When the surfactant is anionic, it isassociated with a positive counterion, for example, Na⁺ or K⁺. When itis zwitterionic, it is associated with both negative and positivecounterions, for example, Cl⁻ and Na⁺ or K⁺. Fluids incorporating VESbased viscosifiers preferably have a viscosity value of at least about50 centipoise at a shear rate of about 100 s⁻¹, at treatmenttemperature.

The viscoelastic surfactant may be, for example, of the followingformulae: R-Z, where R is the hydrophobic tail of the surfactant, whichis a fully or partially saturated, linear or branched hydrocarbon chainof at least 14 carbon atoms and Z is the head group of the surfactantwhich can be -NR₁R₂R₃ ⁺, —SO₃ ⁻, —COO⁻, or, in the case where thesurfactant is zwitterionic, —N⁺(R₁)(R₂)R₃—COO⁻ where R₁, R₂ and R₃ areeach independently hydrogen or a fully or partially saturated, linear orbranched, aliphatic chain of at least one carbon atom; and where R₁ orR₂ can comprise a hydroxyl terminal group; or NR₁R₂O, where thesurfactant is not charged, but an amine oxide.

In other embodiments a cleavable viscoelastic surfactant of thefollowing formula may be used, which is disclosed in the InternationalPatent Application WO02/064945: R—X—Y-Z, where R is the hydrophobic tailof the surfactant, which is a fully or partially saturated, linear orbranched hydrocarbon chain of at least 18 carbon atoms, X is thecleavable or degradable group of the surfactant which is an acetal,amide, ether or ester bond, Y is a spacer group which is constituted bya short saturated or partially saturated hydrocarbon chain of n carbonatoms where n is at least equal to 1, preferably 2 and, when n is equalto or greater than 3, it may be a straight or branched alkyl chain, andZ is the head group of the surfactant which can NR₁R₂R₃ ⁺, —SO₃ ⁻, —COO⁻or, in the case where the surfactant is zwitterionic, —N⁺ (R₁R₂R₃—COO⁻)where R₁, R₂ and R₃ are each independently hydrogen or a fully orpartially saturated, linear or branched, aliphatic chain of at least onecarbon atom, possibly comprising a hydroxyl terminal group. Due to thepresence of the cleavable or degradable group, cleavable surfactants areable to degrade under downhole conditions.

A nonlimiting example of a suitable cationic viscoelastic surfactantuseful for the implementation of the invention is theN-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride. In anaqueous solution of appropriate ionic strength, such as comprising 4 wt% KCl or 3 wt % NH₄Cl, this viscoelastic surfactant forms a gelcontaining worm-like micelles that entangle at surfactant concentrationsabove about 1 wt %. These worm-like micelles collapse to form sphericalmicelles when the gel is exposed to hydrocarbons, resulting in a loss ofviscosity.

Nonlimiting examples of some suitable anionic viscoelastic surfactantsuseful for the implementation of the invention are monocarboxylatesRCOO⁻ such as oleate where R is C₁₇H₃₃ or di- or oligomeric carboxylatessuch as those disclosed in the International Patent Application WO02/11874. These mono-, di- or oligomeric carboxylates form viscoelasticgels when in alkaline solution in the presence of added salts such aspotassium chloride (KCl) or sodium chloride (NaCl). Worm-like micellesof said gel degrade to spherical micelles when the gel is broken byhydrocarbon.

Some examples of zwitterionic surfactants suitable for theimplementation of the invention can be betaine surfactants having thegeneral formula R—N(R₁R₂)-Z where Z is an alkyl group or R—CN(R₁R₂R₃)-Zwhere Z is an acyl group. The hydrophobic group R can be aliphatic oraromatic, straight or branched, saturated or unsaturated. The anionicgroup Z of the surfactant can be —R′—SO₃—, —R′—COO⁻ where R′ is asaturated aliphatic chain. R₁, R₂ and R₃ are each independently hydrogenor an aliphatic chain of at least one carbon atom.

Advantageously, the VES concentration is below about 10 wt %,preferentially, below about 5 wt % and below about 20×c* where c* is theoverlap concentration of the VES. More preferentially, it is comprisedbetween about 0.2×c* and about 5×c*. This corresponds to VESconcentrations far below the viscoelastic surfactant concentration usedin viscoelastic surfactant fracturing fluids of the prior art, which areof the order of from about 30×c* to about 40×c*.

VES viscosified fluids used in some embodiments of the invention arehydrocarbon-responsive so that gel structures break down on contact ormixing with hydrocarbons. The long VES micelles, which form the gelnetwork, degrade on contact with hydrocarbons to form sphericalmicelles. Then, the viscosity of the VES gel decreases to value of about100 mPa-s or below, preferentially, about 20 mPa-s, at a high shearrate.

The fluids used in embodiments of the invention have a leak-off rate,which is below the leak-off rate of pure VES fluids of equivalentrheology. This is a very significant advantage, and as a result, theresponsive fluid of the invention can be used. The fluid loss propertiesof the fluid can be further enhanced by the addition of colloidalparticles, due to a synergistic effect between the fluid loss controladditives and the water inert polymer molecules. Colloidal suspensionsare typically dispersion of discrete very small particles, spherical orelongated in shape, charged so that the repulsion between the samecharged particles stabilizes the dispersion, such as those disclosed inU.S. Pat. No. 7,081,439 (Sullivan, et al.), incorporated herein byreference thereto. Disturbance of the charge balance due for instance byremoving the water, changing the pH or adding salt or water-miscibleorganic solvent, causes the colloidal particles to aggregate resultingin the formation of a gel. The particles are less than 1 micron in size,and typically in the range from about 10 to about 100 nanometers.Commercial solutions of colloidal particles typically include silica(also known as silica sol) and oxides of aluminum, antimony, tin,cerium, yttrium and zirconium. The particles are mostly spherical andparticle sizes may range from about 8 nm to about 250 nm but elongatedparticles, with a length up to 300 nm are also available and were foundto be also acceptable for the invention. The particles may have anegative or positive charge. To be effective as fluid loss controlagent, the solution of colloidal particles are typically added at aconcentration between about 0.1 and 0.5% (ratio of volume of colloidalsolution to the total volume).

Included in fluids comprising the water inert polymer may be an optionalacid particulate matter. The acid particulate matter may become embeddedin, or be in adjacent contact with, the film deposited on the formationface during the placement of the film. The acid particulate matter maydegrade, for example through hydrolysis or other formation factor ortriggering event, to evolve acid monomers. The acid monomers may serveany of several functions including, but not limited to, film breaking,film void creation, pH decrease, and the like, or any combinationthereof. As used herein, the term “dehydration” means substantiallyseparating an aqueous medium from the acid particulate matter,notwithstanding the actual composition of the aqueous medium. The acidparticulate matter used to form the packer generally comprises a solidacid particle that degrades, melts, or releases upon exposure toparticular factors. Such factors include, but are not necessarilylimited to time, temperature, pressure, hydration, or pH. As usedherein, the term “acid particle” means an acid material which may be anacid monomer in an amorphous or crystalline solid state (solid acid), anacid contained within a solid capsule, shell, or coating (encapsulatedacid), and the like. An acid particle may also comprise a polyacid in asolid form, amorphous or crystalline, which is the condensation productof certain organic acid precursors (acid monomers). Such organic acidsare condensed by removal of water to form the polyacid.

Acid and acid ester particles useful in some embodiments of theinvention may be solid or encapsulated. Any suitable acid or acid estermay be used. Examples of suitable acids for forming acid particles ofthe invention, which may be either solid acids or encapsulated liquidacids, include, but are not limited to, hydrochloric acid, sulfuricacid, phosphoric acid, phosphoric acid, nitric acid, formic acid, aceticacid, sulfamic acids, citric acid, glycolic acid, lactic acid Whenencapsulated, the acids may be encapsulated in accordance with themethods described in U.S. Pat. Nos. 5, 373,901, 5,604,186, and 6,357,527and U.S. patent application Ser. No. 10/062,342, filed on Feb. 1, 2002and entitled “Treatment of a Well with an Encapsulated Liquid andProcess for Encapsulating a Liquid,” each of which is incorporated byreference herein in its entirety. Other acids such as maleic acid, boricacid, oxalic acid, sulfamic acid, furmaric acid, , other mineral acids,other organic acids, and the like. Sulfamic acid, boric acid, citricacid, oxalic acid, maleic acid, and the like, are some examples ofsuitable solid acids forming solid acid particles. The acid particlematter may be of any suitable particle size, range of particle size,grade of particles, or plurality of particle sizes, ranges, or grades.The acid particles may be manufactured in various solid shapes,including, but not limited to spheres, granules, fibers, beads, films,ribbons, strips, platelets, and the like.

Some acid particles useful in the invention hydrolyze under known andcontrollable conditions of temperature, time and/or pH to evolve theorganic acid precursors. Any acid particle which is prone to suchhydrolysis may be used in the invention. One example of a suitable acidparticle is a solid polyacid formed from the solid cyclic dimer oflactic acid (known as “lactide”), which has a melting point of 95 to125° C., (depending upon the optical activity). Another is a polymer oflactic acid, (sometimes called a polylactic acid (or “PLA”), or apolylactate, or a polylactide). Another example is the solid cyclicdimer of glycolic acid (known as “glycolide”), which has a melting pointof about 86° C. Yet another example suitable as solid acid-precursorsare those polymers of hydroxyacetic acid (glycolic acid) (“PGA”), withitself or other hydroxy-, carboxylic acid-, or hydroxycarboxylicacid-containing moieties described in U.S. Pat. Nos. 4,848,467;4,957,165; and 4,986,355. Another example is a copolymer of lactic acidand glycolic acid. These polymers and copolymers are polyesters. Aparticular advantage of these materials is that the solid polyacids andthe generated acids are non-toxic and are biodegradable. The solidpolyacids are often used as self-dissolving sutures. Some acid particlescan also be formed by encapsulation of acid precursors such as esters,mono glycerides, diglycerides, triglycerides, polyacrylate copolymerspolymethacrylate copolymers.

Mixtures of one or more acid particles may be used in some embodiments.The mixtures may be purely physical mixtures of separate particles ofseparate components. The mixtures may also be manufactured such that oneor more acid particle and one or more solid acid-reactive materials isin each particle; this will be termed a “combined mixture”. This may bedone, by non-limiting examples, by coating the acid particle materialwith a solid acid-precursor, or by heating a physical mixture until thesolid acid-precursor melts, mixing thoroughly, cooling, and comminuting.For example, it is common practice in industry to co-extrude polymerswith mineral filler materials, such as talc or carbonates, so that theyhave altered optical, thermal and/or mechanical properties. Suchmixtures of polymers and solids are commonly referred to as “filledpolymers”. In any case it is preferable for the distribution of thecomponents in the mixtures to be as uniform as possible. The choices andrelative amounts of the components may be adjusted for the situation tocontrol the acid particle hydrolysis rate.

The amount of acid particle used will be dependent upon the particularrequirements and environment presented. The preferred concentrationrange of acid particles is between from about 0.1 pounds per gallon offluid (ppg) and about 8.34 ppg (between about 0.01 and about 1.0 kg/L).The most preferred range is between about 0.80 ppg and about 2.50 ppg(between about 0.1 and about 0.3 kg/L). One skilled in the art will knowthat for a given particle shape, flow rate, rock properties, etc. thereis an optimum concentration, that can be calculated by one of ordinaryskill in the art.

A gas component may optionally be incorporated into the fluids used insome method embodiments of the invention. The gas component of thefluids of the present invention may be produced from any suitable gasthat forms an energized fluid or foam when introduced into the aqueousmedium. See, for example, U.S. Pat. No. 3,937,283 (Blauer et al.)hereinafter incorporated by reference. Preferably, the gas componentcomprises a gas selected from the group consisting of nitrogen, air,argon, carbon dioxide, and any mixtures thereof. More preferably the gascomponent comprises carbon dioxide, in any quality readily available.The gas component may assist in the fracturing and acidizing operation,as well as the well clean-up process. The fluid may contain from about10% to about 90% volume gas component based upon total fluid volumepercent, preferably from about 30% to about 80% volume gas componentbased upon total fluid volume percent, and more preferably from about40% to about 70% volume gas component based upon total fluid volumepercent.

When a gas component is used in some method embodiments of theinvention, any surfactant or foaming agent for which its ability to aidthe dispersion and/or stabilization of the gas component into the basefluid to form an energized fluid as readily apparent to those skilled inthe art may be used. Viscoelastic surfactants, such as those describedin U.S. Pat. Nos. 6,703,352 (Dahayanake et al.) and 6,482,866(Dahayanake et al.), both incorporated herein by reference, are alsosuitable for use in fluids of the invention. In some embodiments of theinvention, the surfactant is an ionic surfactant. Examples of suitableionic surfactants include, but are not limited to, anionic surfactantssuch as alkyl carboxylates, alkyl ether carboxylates, alkyl sulfates,alkyl ether sulfates, alkyl sulfonates, α-olefin sulfonates, alkyl ethersulfates, alkyl phosphates and alkyl ether phosphates, and anionicsurfactants containing at least one ethylenglycol unit. Examples ofsuitable ionic surfactants also include, but are not limited to,cationic surfactants such as alkyl amines, alkyl diamines, alkyl etheramines, alkyl quaternary ammonium, dialkyl quaternary ammonium and esterquaternary ammonium compounds. Examples of suitable ionic surfactantsalso include, but are not limited to, surfactants that are usuallyregarded as zwitterionic surfactants and in some cases as amphotericsurfactants such as alkyl betaines, alkyl amido betaines, alkylimidazolines, alkyl amine oxides and alkyl quaternary ammoniumcarboxylates. The amphoteric surfactant is a class of surfactant thathas both a positively charged moiety and a negatively charged moietyover a certain pH range (e.g. typically slightly acidic), only anegatively charged moiety over a certain pH range (e.g. typicallyslightly alkaline) and only a positively charged moiety at a differentpH range (e.g. typically moderately acidic), while a zwitterionicsurfactant has a permanently positively charged moiety in the moleculeregardless of pH and a negatively charged moiety at alkaline pH. In someembodiments of the invention, the surfactant is a cationic, zwitterionicor amphoteric surfactant containing an amine group or a quaternaryammonium group in its chemical structure (“amine functionalsurfactant”). A particularly useful surfactant is the amphoteric alkylamine contained in the surfactant solution Aquat 944® (available fromBaker Petrolite of 12645 W. Airport Blvd, Sugar Land, 77478 USA). Inother embodiments of the invention, the surfactant is a blend of two ormore of the surfactants described above, or a blend of any of thesurfactant or surfactants described above with one or more nonionicsurfactants. Examples of suitable nonionic surfactants include, but arenot limited to, alkyl alcohol ethoxylates, alkyl phenol ethoxylates,alkyl acid ethoxylates, alkyl amine ethoxylates, sorbitan alkanoates andethoxylated sorbitan alkanoates. Any effective amount of surfactant orblend of surfactants may be used in aqueous energized fluids of theinvention. Preferably the fluids incorporate the surfactant or blend ofsurfactants in an amount of about 0.02 wt % to about 5 wt % of totalliquid phase weight, and more preferably from about 0.05 wt % to about 2wt % of total liquid phase weight.

In some embodiments, the fluids used may further include a crosslinker.Adding crosslinkers to the fluid may further augment the viscosity ofthe fluid. Crosslinking consists of the attachment of two polymericchains through the chemical association of such chains to a commonelement or chemical group. Suitable crosslinkers may comprise a chemicalcompound containing a polyvalent metal ion such as, but not necessarilylimited to, chromium, iron, boron, aluminum, titanium, antimony andzirconium.

The fluids used in some method embodiments of the invention may includean electrolyte which may be an organic acid, organic acid salt, orinorganic salt. Mixtures of the above members are specificallycontemplated as falling within the scope of the invention. This memberwill typically be present in a minor amount (e.g. less than about 30% byweight of the liquid phase).

The organic acid is typically a sulfonic acid or a carboxylic acid, andthe anionic counter-ion of the organic acid salts is typically asulfonate or a carboxylate. Representative of such organic moleculesinclude various aromatic sulfonates and carboxylates such as p-toluenesulfonate, naphthalene sulfonate, chlorobenzoic acid, salicylic acid,phthalic acid and the like, where such counter-ions are water-soluble.Most preferred organic acids are formic acid, citric acid,5-hydroxy-1-napthoic acid, 6-hydroxy-1-napthoic acid,7-hydroxy-1-napthoic acid, 1-hydroxy-2-naphthoic acid,3-hydroxy-2-naphthoic acid, 5-hydroxy-2-naphthoic acid,7-hydroxy-2-napthoic acid, 1,3-dihydroxy-2-naphthoic acid, and3,4-dichlorobenzoic acid.

The inorganic salts that are particularly suitable include, but are notlimited to, water-soluble potassium, sodium, and ammonium salts, such aspotassium chloride and ammonium chloride. Additionally, magnesiumchloride, calcium chloride, calcium bromide, zinc halide, sodiumcarbonate, and sodium bicarbonate salts may also be used. Any mixturesof the inorganic salts may be used as well. The inorganic salts may aidin the development of increased viscosity that is characteristic ofpreferred fluids. Further, the inorganic salt may assist in maintainingthe stability of a geologic formation to which the fluid is exposed.Formation stability and in particular clay stability (by inhibitinghydration of the clay) is achieved at a concentration level of a fewpercent by weight and as such the density of fluid is not significantlyaltered by the presence of the inorganic salt unless fluid densitybecomes an important consideration, at which point, heavier inorganicsalts may be used. In a preferred embodiment of the invention, theelectrolyte is potassium chloride. The electrolyte is preferably used inan amount of from about 0.01 wt % to about 12.0 wt % of the total liquidphase weight, and more preferably from about 1.0 wt % to about 8.0 wt %of the total liquid phase weight.

Fluids used in some embodiments of the invention may also comprise anorganoamino compound. Examples of suitable organoamino compoundsinclude, but are not necessarily limited to, tetraethylenepentamine,triethylenetetramine, pentaethylenhexamine, triethanolamine, and thelike, or any mixtures thereof. When organoamino compounds are used influids of the invention, they are incorporated at an amount from about0.01 wt % to about 2.0 wt % based on total liquid phase weight.Preferably, when used, the organoamino compound is incorporated at anamount from about 0.05 wt % to about 1.0 wt % based on total liquidphase weight. A particularly useful organoamino compound istetraethylenepentamine.

Friction reducers may also be incorporated into fluids used in theinvention. Any friction reducer may be used. Also, polymers such aspolyacrylamide, polyisobutyl methacrylate, polymethyl methacrylate andpolyisobutylene as well as water-soluble friction reducers such as guargum, guar gum derivatives, hydrolyzed polyacrylamide, and polyethyleneoxide may be used. Commercial drag reducing chemicals such as those soldby Conoco Inc. under the trademark “CDR” as described in U.S. Pat. No.3,692,676 (Culter et al.) or drag reducers such as those sold byChemlink designated under the trademarks “FLO 1003, 1004, 1005 & 1008”have also been found to be effective. These polymeric species added asfriction reducers or viscosity index improvers may also act as excellentfluid loss additives reducing or even eliminating the need forconventional fluid loss additives.

Breakers, in addition to those described above, may optionally be usedin some methods of the invention. The purpose of this component is to“break” or diminish the viscosity of the fluid so that this fluid iseven more easily recovered from the formation during cleanup. Withregard to breaking down viscosity, oxidizers, enzymes, or acids may beused. Breakers reduce the polymer's molecular weight by the action of anacid, an oxidizer, an enzyme, or some combination of these on thepolymer itself. In the case of borate-crosslinked gels, increasing thepH and therefore increasing the effective concentration of the activecrosslinker (the borate anion), will allow the polymer to becrosslinked. Lowering the pH can just as easily eliminate theborate/polymer bonds. At pH values at or above 8, the borate ion existsand is available to crosslink and cause gelling. At lower pH, the borateis tied up by hydrogen and is not available for crosslinking, thusgelation caused by borate ion is reversible. Preferred breakers include0.1 to 20 pounds per thousands gallons of conventional oxidizers such asammonium persulfates, live or encapsulated, or potassium periodate,calcium peroxide, chlorites, and the like. In oil producing formationsthe film may be at least partially broken when contacted with formationfluids (oil), which may help de-stabilize the film.

A fiber component may be included in the fluids used in the invention toachieve a variety of properties including improving particle suspension,and particle transport capabilities, and gas phase stability. Fibersused may be hydrophilic or hydrophobic in nature, but hydrophilic fibersare preferred. Fibers can be any fibrous material, such as, but notnecessarily limited to, natural organic fibers, comminuted plantmaterials, synthetic polymer fibers (by non-limiting example polyester,polyaramide, polyamide, novoloid or a novoloid-type polymer),fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers,metal fibers, metal filaments, carbon fibers, glass fibers, ceramicfibers, natural polymer fibers, and any mixtures thereof. Particularlyuseful fibers are polyester fibers coated to be highly hydrophilic, suchas, but not limited to, DACRON® polyethylene terephthalate (PET) Fibersavailable from Invista Corp. Wichita, Kans., USA, 67220. Other examplesof useful fibers include, but are not limited to, polylactic acidpolyester fibers, polyglycolic acid polyester fibers, polyvinyl alcoholfibers, and the like. When used in fluids of the invention, the fibercomponent may be included at concentrations from about 1 to about 15grams per liter of the liquid phase of the fluid, preferably theconcentration of fibers are from about 2 to about 12 grams per liter ofliquid, and more preferably from about 2 to about 10 grams per liter ofliquid.

Embodiments of the invention may use fluids further containing otheradditives and chemicals that are known to be commonly used in oilfieldapplications by those skilled in the art. These include, but are notnecessarily limited to, materials such as surfactants in addition tothose mentioned hereinabove, breaker aids in addition to those mentionedhereinabove, oxygen scavengers, alcohols, scale inhibitors, corrosioninhibitors, fluid-loss additives, bactericides, and the like. Also, theymay include a co-surfactant to optimize viscosity or to minimize theformation of stabilized emulsions that contain components of crude oil,or as described hereinabove, a polysaccharide or chemically modifiedpolysaccharide, natural polymers and derivatives of natural polymers,such as cellulose, derivatized cellulose, guar gum, derivatized guargum, or biopolymers such as xanthan, diutan, and scleroglucan, syntheticpolymers such as polyacrylamides and polyacrylamide copolymers,oxidizers such as persulfates, peroxides, bromates, chlorates,chlorites, periodates, and the like.

Conventional propped hydraulic fracturing methods, with appropriateadjustments if necessary, as will be apparent to those skilled in theart, are used in the methods of the invention. One preferred fracturestimulation treatment according to the present invention typicallybegins with a conventional pad stage to generate the fracture, followedby a sequence of stages in which a viscous carrier fluid transportsproppant into the fracture as the fracture is propagated. Typically, inthis sequence of stages the amount of propping agent is increased,normally stepwise. The pad and carrier fluid can be, and usually are, agelled aqueous fluid, such as water or brine thickened with aviscoelastic surfactant or with a water soluble or dispersible polymersuch as guar, hydroxypropylguar or the like. The pad and carrier fluidsmay contain various additives. Non-limiting examples are fluid lossadditives, crosslinking agents, clay control agents, breakers and thelike, provided that the additives do not affect the stability or actionof the fluid.

The procedural techniques for pumping fracture stimulation fluids down awellbore to fracture a subterranean formation are well known. The personthat designs such fracturing treatments is the person of ordinary skillto whom this disclosure is directed. That person has available manyuseful tools to help design and implement the fracturing treatments, oneof which is a computer program commonly referred to as a fracturesimulation model (also known as fracture models, fracture simulators,and fracture placement models). Most if not all commercial servicecompanies that provide fracturing services to the oilfield have one ormore fracture simulation models that their treatment designers use. Onecommercial fracture simulation model that is widely used by severalservice companies is known as FracCADE™. This commercial computerprogram is a fracture design, prediction, and treatment-monitoringprogram designed by Schlumberger, Ltd. All of the various fracturesimulation models use information available to the treatment designerconcerning the formation to be treated and the various treatment fluids(and additives) in the calculations, and the program output is a pumpingschedule that is used to pump the fracture stimulation fluids into thewellbore. The text “Reservoir Stimulation,” Third Edition, Edited byMichael J. Economides and Kenneth G. Nolte, Published by John Wiley &Sons, (2000), is an excellent reference book for fracturing and otherwell treatments; it discusses fracture simulation models in Chapter 5(page 5-28) and the Appendix for Chapter 5 (page A-15)), which areincorporated herein by reference.

Embodiments of the invention may also include placing proppant particlesthat are substantially insoluble in the fluids of the formation.Proppant particles carried by the treatment fluid remain in the fracturecreated, thus propping open the fracture when the fracturing pressure isreleased and the well is put into production. Suitable proppantmaterials include, but are not limited to, sand, walnut shells, sinteredbauxite, glass beads, ceramic materials, naturally occurring materials,or similar materials. Mixtures of proppants can be used as well. If sandis used, it will typically be from about 20 to about 100 U.S. StandardMesh in size. Naturally occurring materials may be underived and/orunprocessed naturally occurring materials, as well as materials based onnaturally occurring materials that have been processed and/or derived.Suitable examples of naturally occurring particulate materials for useas proppants include, but are not necessarily limited to: ground orcrushed shells of nuts such as walnut, coconut, pecan, almond, ivorynut, brazil nut, etc.; ground or crushed seed shells (including fruitpits) of seeds of fruits such as plum, olive, peach, cherry, apricot,etc.; ground or crushed seed shells of other plants such as maize (e.g.,corn cobs or corn kernels), etc.; processed wood materials such as thosederived from woods such as oak, hickory, walnut, poplar, mahogany, etc.including such woods that have been processed by grinding, chipping, orother form of particalization, processing, etc. Further information onnuts and composition thereof may be found in Encyclopedia of ChemicalTechnology, Edited by Raymond E. Kirk and Donald F. Othmer, ThirdEdition, John Wiley & Sons, Volume 16, pages 248-273 (entitled “Nuts”),Copyright 1981, which is incorporated herein by reference.

The concentration of proppant in the fluid can be any concentrationknown in the art, and will preferably be in the range of from about 0.05to about 3 kilograms of proppant added per liter of liquid phase. Also,any of the proppant particles can further be coated with a resin topotentially improve the strength, clustering ability, and flow backproperties of the proppant.

EXAMPLES Examples 1 through 3

In these examples the water inert polymer, in the form of an emulsion,is blended with a conventional fracturing fluid during early stages ofthe treatment (pad), and the rheology of the fluid with and without thewater inert polymer is compared to ensure that adequate viscosity isdeveloped and maintained for fracturing. The pad fluid contained 40 pptguar gum supplied by Economy Polymers and Chemicals, Houston, Tex.77245-0246, the guar being crosslinked with a borate crosslinker (4 pptof Boric Acid, with a pH adjusted to ˜11 using a 30% weight aqueoussolution of caustic soda). The emulsion added was ChemCor PolyEMULSION330N35. The graph in FIG. 1 shows the viscosity, measured using aconventional Fann 50 rheometer, of the pad fluid containing no emulsion(Example 1), 1% by weight of ChemCor HDPE PolyEMULSION 330N35 emulsionbased upon total fluid weight (Example 2), and 2.5% by weight of ChemCorHDPE PolyEMULSION 330N35 emulsion based upon total fluid weight (Example3). The pad fluid also included DI water, contained a 50% by weightaqueous solution of tetra methyl ammonium chloride clay stabilizer addedat 2 gpt, and 1 gpt of a 85% by weight solution of triethanol amine hightemperature stabilizer.

The fluids of Examples 2 and 3 showed improved viscosity stability andrheology up to 250° F. This also illustrates that the water inertpolymer emulsion is not degrading fluid performance and is thereforecompatible with the pad fluid and conventional additives, such as claystabilizers and temperature stabilizers, used in fracturing operations.Also tested and providing like rheology trends was ChemCor'spolyEMULSION 629N40 emulsion polymer.

Examples 4 through 7

In examples 4 through 7, and referring to FIG. 2, the fluid loss ismeasured on samples with a water inert polymer, in the form of anemulsion, blended with conventional fracturing pad fluids, and fluidloss is determined for the fluid with and without the water inertpolymer. The pad fluids contained 25 ppt guar gum supplied by EconomyPolymers and Chemicals, the guar being crosslinked with a boratecrosslinker (4 ppt of Boric Acid, with a pH adjusted to 11 with causticsoda). The pad fluid also included DI water, contained a 50% by weightaqueous solution of tetra methyl ammonium chloride clay stabilizer addedat 2 gpt, and 1 gpt of a 85% by weight solution of triethanol amine hightemperature stabilizer. In examples 5 through 7, the emulsion added wasChemCor PolyEMULSION 330N35.

The fluids were evaluated on a static fluid loss cell using 1″ diametercores of varied permeability at temperature with 1200 psi total pressureand 200 psi back pressure, for a net pressure of 1000 psi. The cores(Nugget sandstones cores) of permeability 1.4 mD without emulsion(Example 4), with 1% by weight of emulsion based upon total fluid weight(Example 5) (core permeability 2.1 mD), with 5% by weight of emulsionbased upon total fluid weight (Example 6) (Core permeability 3.2 mD),and 10% by weight of emulsion based upon total fluid weight (Example 7)(Core permeability 2.7 mD). As shown in the curves of FIG. 2, theseexamples illustrate how the inclusion of a water inert polymer atincreased concentration into the pad fluid significantly andprogressively decreases fluid leak-off.

Examples 8 through 15

For examples 8 through 15, pad fluids, formulated in accordance with thepad fluids of examples 1 and 4 above, with and without either ChemCORPolyEMULSION 330N35 or polyEMULSION 629N40, were tested at differenttemperatures and normalized leak-off coefficients (C_(w)/sqrt(K))determined and reported in FIG. 3. C_(w) is discussed in Navarrete, R.C., Caweizel, K. E., and Constien, V. G.: “Dynamic Fluid Loss inHydraulic Fracturing Under Realistic Shear Conditions in High-Permeability Rocks,” SPE Production and Facilities, pp 138-143 (August,1996). To determine leak-off rates, experiments were conducted in aconventional static fluid loss cell at 1200 psi total pressure and aback pressure of 200 psi, giving a total net pressure across the core of1000 psi. The core was held at constant temperature, as indicated inFIG. 3, and the fluid collected at the discharge of the core. The rateof fluid leaking off through the core was measured as a function oftime. The slope of the volume leaking off as a function of the squareroot of time was measured and reported as being the C_(w) coefficient.The C_(w) coefficient was divided by the square root of the permeability(an indication of the diameter of the pore size of the core used) tonormalize the leak-off rate. Using this normalization approach, theC_(w) coefficients for a given system will be consistent over the rangeof permeabilities tested. As shown in FIG. 3, the inclusion of a waterinert polymer into the pad fluid significantly improves significantlyfluid leak-off. C_(w) is expressed in units of ft/mm^(1/2), while C_(w)/Sqrt (K) in units of ft/(mm^(1/2) *milli-Darcy^(1/2))

Examples 16 and 17

Fluid loss tests using a conventional static fluid loss cell, with cores1″ in diameter and 3.61 mD permeability, at 185° F., 1200 psi totalpressure, and 200 psi back pressure, were run with and withoutpersulfate breaker to evaluate film removal. FIG. 4 displays the fluidloss of a 40 ppt crosslinked gel formed from guar gum from EconomyPolymers and Chemicals crosslinked with 5 ppt of boric Acid, along withChemCOR polyEMULSION 629N40 added at 10% by weight based total fluidweight, where the pH of the solution was adjusted to pH 11 using a 30%solution by weight of caustic soda solution. The aqueous fluidscontained 2 gpt liquid clay stabilizer (a 50% solution by weight oftetra methyl ammonium chloride in water solution) and a high temperaturestabilizer at 2 gpt liquid (a 25% solution by weight of triethanolamine) In example 16, ammonium persulfate was incorporated in the fluidat 5 ppt and placed in a first cell (Example 16) at the time indicatedby the arrow on FIG. 4. No persulfate was placed in a second cell(Example 17), and the fluid loss rate was not significantly changed.Potassium periodate was also evaluated in similar fashion and proved tobe effective.

In Examples 18 through 39, water inert polymers formed of latexes wereevaluated illustrating their performance according to the invention.

Examples 18 through 23

Several available latex polymers were evaluated for their rheologicaleffect on treatment fluids. They included nanolatex of acrylic copolymerlatexes of VA/VeOVA, MMA (vinyl acetate, vinylester of versatic acid,methyl methacrylate), etc. In these cases the latexes did not haveenough viscosity to create the fracture itself, however, blended withconventional fracturing fluids they showed good rheology. For exampleFIG. 5 shows the rheology of a 25 ppt crosslinked guar system preparedwith 2 gpt of a liquid clay stabilizer solution. The 25 ppt gel wascrosslinked with 4 ppt boric acid and the pH was adjusted to 11 withcaustic soda. In all cases, the latex polymer studied was added to thefluid at a rate of 10% by weight, based upon total fluid weight.

Latex 1 (Example 18) is a nanolatex of acrylic copolymers, RhodoPASS® LS5000 supplied by Rhodia, latexes 2 (Example 19) and 3 (Example 20) areformed from vinyl acetate and vinylester of versatic acid, available asAV29 from Rhodia, latex 5 (Example 22) is based upon vinyl alcohol,vinyl versatate and dibutyl maleate, while latex 6 (Example 23) isformed from methyl methacrylate, acrylic acid, and 2-ethyl hexylacrylate. The rheology of the fracturing fluid with and without thelatexes is consistent and would allow for opening a fracture in therock.

The latexes were also tested under different temperature with variousloadings and the data were consistent across a large range oftemperature. Temperatures ranged from 85° F. to 200° F. usingconcentrations from 1% to 20% by weight, based upon total fluid weight.

Examples 24 through 28

FIGS. 6, 7 & 8 represent the values of fluid loss measured for differentcores using different latex concentrations at different temperatures.For example, FIG. 6 is a plot of the C_(w) coefficients measured on 5different cores at 85° F. with various amount of latex, examples 24through 28. The C_(w) coefficient have been normalized by the squareroot of the permeability of the core to take into account the estimatedpore diameter of the core. Each point corresponds to a static fluid lossexperiment run as described above for a 25 ppts gel (Guar from EconomyPolymers & Chemicals) crosslinked with 5 ppt boric acid and where the pHwas adjusted to pH ˜10 with a 30% solution by weight of caustic soda.The fluid loss was measured and recorded at 85° F., and C_(w)coefficient calculated and normalized against the square root of thepermeability of the core and the data plotted for different latexconcentrations. No latex was used for example 24. The latex used inexamples 25 through 28 is a latex of vinyl acetate and VeOVA (branchedalcohol) of average particle size ˜2 micrometer, supplied as AV29 fromRhodia. The latex was incorporated into the above fluids at theconcentrations given in FIG. 6. FIG. 6 shows that increasing latexconcentration lowers the fluid loss coefficient, and improves fluidefficiency. FIG. 7 is the same data as FIG. 6, but reported differently.In FIG. 7, the fluid loss coefficients are reported as a function of thelatex concentration, thus further illustrating the advantage ofincorporating water inert polymer to improve fluid efficiency. Note thatin example 24, the C_(w)/Sqrt (K) is about 0.0014, and the addition oflatex reduced this value to less than 0.0014, in all cases. For example25, C_(w)/Sqrt (K) was about 0.0008, about 0.0004 for example 26, about0.0003 for example 27, and about 0.0002 for example 28.

Examples 29 through 33

The graph in FIG. 8 is similar with that of FIG. 6, but differs in thatdifferent latexes, and blends of latexes, were used as film formingmaterials. Each point corresponds to a static fluid loss experiment runas described above for a 25 ppt gel (Guar from Economy Polymers &Chemicals) crosslinked with 5 ppt Boric Acid, and where the pH wasadjusted to pH ˜10 with a 30% solution by weight of caustic soda. Thefluid loss was measured and recorded at 85° F., the C_(w) coefficientcalculated and normalized against the square root of the permeability ofthe core and the data plotted for different latex concentration orcombination. In one case, a blend of latexes was used, where the latexeshad different particle size. The latex A is a nanolatex acryliccopolymer from Rhodia supplied as RhodoPASS® LS 5000, having an averageparticle size of about 0.06 micrometer, while the latex AV29 from Rhodiais a latex of vinyl alcohol and other branched alcohols of about 2micrometer average particle size. The data show that using a blend oftwo different latexes of different particle size increased significantlythe efficiency of the film forming material, since the fluid losscoefficient of the film formed with 10% by weight of a latex Acorrespond to the same value as the fluid loss coefficient of a filmformed with 2.5% of the latex blend with 2.5% nanolatex (example 33).

Examples 34 through 36

FIG. 9 illustrates the results of a conventional static fluid loss testusing 1″ cores. The fluid loss was run at 1000 psi net pressure at 125°F. with a 25 ppt guar from Economy Polymer and Chemicals crosslinkedwith 5 ppt of Boric Acid and where the pH of the solution was adjustedusing a 30% solution by weight of caustic soda to a value close to 10.5.The different fluid loss cells each contained the 25 ppt crosslinkedgel, blended in a conventional liquid solution of clay stabilizer (a 50%solution by weight of tetra methyl ammonium chloride) and from the leftto the right, no other additives (example 34), 15% by weight of AV22latex available from Rhodia (a latex of VA/VeOVA of 2 micrometer inaverage particle size) (example 35), and 20% by weight of the same latex(example 36). The experiment was run over 4 hours and the cores wereremoved from the fluid loss cell and the pictures were taken. Thepicture on the left shows a conventional filter cake built from the 25ppt crosslinked gel, while the pictures on the right show a much thinnerfilm formed upon dehydration of the fluid and concentration of thelatexes.

Examples 37 through 39

Referring now to FIG. 10, examples 37 through 39 illustrate theadditional advantage of using a latex water inert polymer in conjunctionwith a fluid loss additive. The fluids were evaluated on a static fluidloss cell using 1″ diameter cores of varied permeability at temperature.The fluid loss was run at 1000 psi net pressure at 100° F. with a 25 pptguar from Economy Polymer and Chemicals crosslinked with 5 ppt of BoricAcid and where the pH of the solution was adjusted using a 30% solutionby weight of caustic soda to a value close to 10.5. The different fluidloss cells contained each the 25 ppt crosslinked gel a conventionalliquid solution of clay stabilizer (a 25% solution by weight of tetramethyl chloride). The cores used were of different but closepermeabilities: (Nugget sandstones cores) 1.2 mD with the fluid lossadditive (example 37), 2.6 mD with the 10% by weight latex suspension(example 38), and 2 mD with the mixture of fluid loss additive and the10% suspension of latex (example 39). As shown in the curves of FIG. 10,these examples illustrate the synergy between the solid particles of thefluid loss additives with the latex particles, since the leak off issignificantly reduced when the two components are added simultaneously.The fluid loss with conventional fluid loss additive is further improvedwhen used with a water inert latex polymer. In this example the latexused is Latex Terpo 600B from Rhodia and the fluid loss additive used isa conventional mixture of starch and mica.

Examples 40 and 41

Referring to FIG. 11, and examples 40 and 41, here the fluids wereevaluated on a static fluid loss cell using 1″ diameter cores of variedpermeability at temperature. The fluid loss was run at 1000 psi netpressure at 100° F. with a 10% by weight of viscoelastic surfactant(VES) based viscosifier solution. The VES solution included about 60% byweight (Z)-13 docosenyl-N-N-bis (2-hydroxyethyl) methyl ammoniumchloride, about 13% by weight propane-1,2-diol, about 20% by weightpropan-2-ol, and about 7% water. The VES solution was evaluated without(example 40) and with a 5% by weight of ChemCOR PolyEMULSION 330N35(example 41). The cores had peremeability values of about 2.3 mD. Thedifferent fluid loss cells each contained a conventional liquid solutionof clay stabilizer (4% by weight of Potassium Chloride). As shown in thecurves of FIG. 11, these examples illustrate that the fluid loss issignificantly decreased for VES carrying fluids with the use of a filmforming material.

Although the methods have been described here for, and are mosttypically used for, hydrocarbon production, they may also be used ininjection wells and for production of other fluids, such as water orbrine. The particular embodiments disclosed above are illustrative only,as the invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details herein shown, other than as described in theclaims below. It is therefore evident that the particular embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the invention. Accordingly,the protection sought herein is as set forth in the claims below.

1.-34. (canceled)
 35. A method of treat a subterranean formationpenetrated by a wellbore, the method comprising: a. preparing an aqueousfluid comprising at least one water inert polymer, provided that noviscosifier is added to the aqueous fluid to substantially increase thefluid viscosity; and, b. injecting the aqueous fluid into the wellboreat a pressure equal to or greater than the formation's fractureinitiation pressure.
 36. The method of claim 35 wherein the at least onewater inert polymer comprises at least one emulsion polymer.
 37. Themethod of claim 35 wherein the at least one water inert polymercomprises at least one latex polymer.
 38. The method of claim 35 furthercomprising: c. thereafter injecting into the wellbore a proppant ladenfluid at a pressure equal to or greater than the formation's fractureinitiation pressure.
 39. The method of claim 35 wherein the leak offcoefficient for the aqueous fluid is less than about 0.0022.
 40. Themethod of claim 39 wherein the leak off coefficient for the aqueousfluid is equal to or less than about 0.0010.
 41. The method of claim 38with the provisio that no conventional fluid loss additive isincorporated into the aqueous fluid nor the proppant laden fluid. 42.The method of claim 35 wherein the aqueous fluid further comprises afluid loss additive.
 43. The method of claim 38 wherein the water inertpolymer forms a film on fracture faces, the method further comprisingdegrading the film subsequent to injecting the proppant laden fluid. 44.The method of claim 43 wherein the film is degraded with breaker, thebreaker selected from the group consisting of delayed breakers,conventional oxidizers, oxidizers triggered by catalysts contained inthe film, latent acids, or formation fluids.
 45. The method of claim 35wherein the aqueous treatment fluid further comprises colloidalparticles.
 46. The method of claim 35 wherein the aqueous treatmentfluid further comprises at least one friction pressure reducing agent.47. The method of claim 36 provided that the water inert polymer is nota fluid loss additive.
 48. A method of treating a subterranean formationpenetrated by a wellbore, the method comprising: a. preparing an aqueousfluid comprising at least one water inert polymer and a viscosifier;and, b. injecting the aqueous fluid into the wellbore at a pressureequal to or greater than the formation's fracture initiation pressure;and wherein the leak off coefficient for the aqueous fluid is less thanabout 0.0022.
 49. The method of claim 48 further comprising: c.thereafter injecting into the wellbore a proppant laden fluid at apressure equal to or greater than the formation's fracture initiationpressure.;
 50. The method of claim 49 wherein the at least one waterinert polymer comprises at least one emulsion polymer.
 51. The method ofclaim 49 wherein the at least one water inert polymer comprises at leastone latex polymer.
 52. The method of claim 49 wherein the viscosifier isselected from the group consisting of viscoelastic surfactants, naturalpolymers, derivatives of natural polymers, synthetic polymers,biopolymers, and the like, or any mixtures thereof.
 53. The method ofclaim 49 wherein the viscosifier is selected from the group consistingof natural polymers, derivatives of natural polymers, syntheticpolymers, and biopolymers, the viscosifier incorporated in an amountless than about 30 lbs per thousand gallons of aqueous treatment fluid,preferably less than about 25 lbs per thousand gallons of aqueoustreatment fluid, more preferably less than about 20 lbs per thousandgallons of aqueous treatment fluid.
 54. A method for reducing matrixdamage to a formation during a treatment operation, the methodcomprising injecting into a wellbore penetrating the formation, anaqueous treatment fluid comprising at least one water inert polymer,wherein the leak off coefficient for the aqueous fluid is less thanabout 0.0022.
 55. The method of claim 54 wherein the fluid injected at apressure equal or greater than the formation's fracture initiationpressure.